In the Dan field, very high breakdown pressures were observed for wellbores drilled with a high azimuth with respect to the preferred fracture plane. The increased breakdown pressure was caused by significant near-wellbore friction. In scaled laboratory tests, variation in breakdown pressure was accompanied by a change in fracture geometry. Therefore, the variation in breakdown pressure in the field treatments could not be related simply to in-situ stresses.

Summary We have derived model laws that relate experimental parameters of a physical model of hydraulic fracture propagation to the prototype parameters. Correct representation of elastic deformation, fluid friction, crack propagation, and fluid leakoff forms the basis of the scaling laws. For tests at in-situ stress, high fluid viscosity and low fracture toughness are required. Tests on cement blocks agreed with the scale laws based on elastic behavior. Introduction In hydraulic fracture treatment design, numerical simulation is used to relate measured pressure to fracture geometry. As yet, there is no way to observe fracture geometry in field treatments, except in special tests with extensive monitoring (e.g., Ref. 1). Even then, much room is left for data interpretation. Laboratory tests should therefore serve as benchmarks for numerical simulations. Although there is an enormous difference in the scale of fractures in laboratory tests and in field applications, a numerical model should at least be capable of describing model tests with the appropriate boundary conditions. Many researchers have attempted to study fracture growth in physical model tests. Still, we must critically review previous experimental work in this paper because we think that such efforts can be greatly improved, at least in regard to two important (related) issues: correct scaling of the physical phenomena and stability of fracture propagation. Correct scaling implies that the physics of fluid-driven fracture propagation at field scale must be represented in the test. For instance, if tests are set up at in-situ stress and water is used for fracturing in the laboratory, the fracture pressures required to produce reasonable experimental times (and stable crack propagation) become so low that fracture toughness dominates the process, which is contrary to field observations (e.g., equal pressures during initial propagation and fracture reopening). In addition, the nonpenetrated zone at the fracture tip will disappear and the fracture will grow dynamically. Such experiments can bear no relation to the quasistatic process implied by field conditions nor to any credible numerical simulation of field fracturing.

Recent improvements in tilt measurement techniques have greatly enhanced the resolution of hydraulic fracture-induced tilts, resulting in both greater mapping precision and an increase in the maximum mapping depth achievable with a surface tiltmeter array. With a previous depth limitation of around 6,000 ft., surface tiltmeter mapping was limited to areas with relatively shallow production. Application is greatly broadened now with a depth range down to 10,000 ft. In addition to the expanded depth range, there has been a marked improvement in the fracture mapping resolution. This paper begins with an overview of the tiltmeter fracture mapping concept, highlighting both the strengths of this technique and its limitations. Following that is a description of the technical advancements made over the last three years to allow fracture mapping at far greater depths. Finally, two brief case studies are presented to demonstrate fracture mapping at great depth, and also to provide insight on hydraulic fracture growth behavior in two different environments. As the case studies make clear, fracture growth is far more complex than is generally assumed. Better understanding of these complexities can lead to significantly enhanced fracture stimulation practices. P. 135

A new fracture diagnostic technology for mapping hydraulic fracture dimensions is introduced: downhole tiltmeter fracture mapping. Downhole tilt fracture mapping involves deploying wireline-conveyed tiltmeter arrays in offset wellbores to measure hydraulic fracture growth versus time. This technology has been employed to map over 100 fracture treatments in the last eighteen months. Allowing, for the first time, the gathering of statistically significant data-sets on how hydraulic fractures actually do grow - albeit, within only a few fields so far. In addition to providing fracture diagnostic data (fracture length, height, width and asymmetry), this new capability allows enhanced utilization of hydraulic fracture models because model predictions can be "calibrated" with insitu observations of fracture growth. The mapping concept is quite simple: creating a hydraulic fracture involves parting the rock and deforming the reservoir. Downhole tiltmeter mapping involves measuring the fracture-induced deformation in a nearby offset well(s) versus time and depth and inverting the data to obtain the created fracture dimensions. The principles are the same as for surface tiltmeter mapping, but the different array geometry make it very sensitive to fracture dimensions and less sensitive to fracture orientation - just the reverse of surface tiltmeter mapping. This paper will explain the fundamental concepts, the implementation strategy (wireline arrays, processing and modeling), present three field case studies, and briefly discuss the implications on fracture modeling. P. 585

Conventional wisdom regarding horizontal hydraulic fractures is that they are common in shallow environments but that they generally do not occur below a "critical" depth of about 2000 ft. However, direct measurement of hydraulic fracture orientation utilizing tiltmeter fracture mapping on wellover 1000 fracture treatments has shown that hydraulic fracture growth behavioris much more complex than implied by this simple "rule of thumb". Horizontal hydraulic fractures are far more common than generally believed. This paper documents the widespread occurrence of horizontal fractures in two classes of environments:reservoirs with high horizontal stresses, including an example at 7,500 ft.; andreservoirs undergoing Enhanced Oil Recovery (EOR) where the distribution of the overburden load (vertical stress) has been altered such that horizontal fractures are created even when fracture pressure gradients are well below the overburden gradient as estimated from an integrated density log. Fracture mapping data is presented from three different fields. The Lost Hills Field in California exhibits a curious stress state where the shallow estzones at the top of the thick diatomite reservoir (1000 – 2000 ft.) yield near vertical hydraulic fractures, but stimulating the deeper zones often creates horizontal hydraulic fractures due to a stress state "reversal" with depth. Fracture orientation data is also presented from the 7,500 ft. deep North Shafter Field where one treatment resulted in a (near) horizontal hydraulic fracture(s) that resulted in a very early premature treatment screenout, in contrast to another nearby fracture treatment where a dominant (near) vertical fracture was created and there was no difficulty placing all 400,000 lb. of proppant. These two fields illustrate "unconventional" original insitu stress states that result in significant horizontal fracture growth at depth. The third example presented, in the massive Belridge oil field, illustrates a much different phenomenon where the original stress state generally resulted in near vertical hydraulic fractures throughout the entire interval. However, secondary recovery has sufficiently altered the stress state such that horizontal fracture growth is becoming very significant. Direct fracture intersection of nearby wells has confirmed the creation of horizontal hydraulic fractures in many wells in the Belridge Field, even when the observed fracture gradients are well below the integrated density log estimates of the overburden stress. We believe that this is due to a "room and pillar" vertical stress state that is created by the highly variable reservoir pressure profile induced by secondary recovery (water flooding), with a lower local vertical stress around producer wells and higher vertical stress around injector wells.